Thermally Assisted Oil Production Wells

ABSTRACT

A method and system are shown that conditions an underground reservoir by flooding the reservoir with a heated fluid to transfer heat to the underground reservoir and cause oil and gas to increase flow during recovery from the underground reservoir, wherein the fluid is heated by heat from a geothermal well, or heated by heat generated by burning gas recovered from the underground reservoir, or heated by heat from both a geothermal well and heat generated by burning gas recovered from the underground reservoir, and recovering the oil and gas with the increased flow.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims the benefit of U.S. Provisional Patent Application Ser. No. 62/061,437 filed Oct. 8, 2014, U.S. Provisional Patent Application Ser. No. 62/061,426 filed Oct. 8, 2014, and U.S. Provisional Patent Application Ser. No. 62/061,420 filed Oct. 8, 2014, each of which are hereby incorporated by reference in their entirety.

FIELD OF THE INVENTION

The present invention relates to thermally-assisted oil production wells, for use in recovering oil from an oil reservoir.

BACKGROUND OF THE INVENTION

In petroleum geology, a reservoir is a porous and permeable lithological unit or set of units in a formation that hold hydrocarbon reserves such as crude oil and natural gas. The flow rate (Q) of the hydrocarbon reserves through such a formation may be determined according to Darcy's Law:

$Q = {\frac{\kappa \; A}{\mu} \cdot \frac{\partial p}{\partial x}}$

where Q is the flowrate (in units of volume per unit time), κ is the relative permeability of the formation (typically in millidarcies), A is the cross-sectional area of the formation, μ is the viscosity of the fluid (typically in units of centipoise), and ∂p/∂x represents the pressure change per unit length of the formation that the fluid will flow through.

Crude oil viscosity (κ) is its resistance to flow. It may be viewed as a measure of its internal friction such that a force is needed to cause one layer to slide past another. Newton's law of viscosity states that the shear stress between adjacent fluid layers is proportional to the negative value of the velocity gradient between the two layers. Alternatively, the law may be interpreted as stating that the rate of momentum transfer per unit area, between two adjacent layers of fluid, is proportional to the negative value of the velocity gradient between them. The unit of viscosity in cgs units is dyne·sec/cm² (1 dyne-sec/cm² is called a poise (P)). From the units, it will be evident that viscosity has dimensions of momentum per unit area. One Poise (P) in mks units is 0.1 kg·m⁻¹·s⁻¹. The SI unit for viscosity is the pascal·second (Pa·s) which equals 10P. A centipoise is one-hundredth of a poise and one millipascal·second (mPa·s). FIG. 1a shows (on the left hand side) various types of crude oil with viscosities indicated on a vertical logarithmic scale in centipoise as compared to familiar substances on the right hand side aligned along the same scale.

API (American Petroleum Institute) gravity is an inverse measure of the relative density, as compared to water, of crude oil. It is measured in units called API degrees (°API). The lower the number of API degrees, the higher the specific gravity of the oil. If greater than 10, the oil floats in water. If less than 10, it sinks in water. FIG. 1b shows a rough correlation between crude oil viscosity (cp) versus API gravity for five different temperatures (five curves, from left to right, at 180 C, 140 C, 100 C, 60 C, and 20 C). For a given temperature curve, e.g., the top curve at 20 C, it is clear that a light crude with API>30 will have a viscosity much lower than a heavy crude with API<22. The ratio of fluid viscosity to density is called kinematic viscosity and is indicative of the ability of the fluid to transport momentum. It has dimensions of L²t⁻¹. It is also referred to as the momentum diffusivity of the fluid.

The permeability to flow through a rock for the case where a single fluid is present is different when other fluids are present in the reservoir. Saturation, the proportion of oil, gas, water and other fluids in a rock is a crucial factor in a pre-development evaluation of the reservoir. The relative saturations of the fluids as well as the nature of the reservoir affect the permeability. Crude oil mobility (λ₀) is the ratio of the effective permeability (κ₀) to the oil flow to its viscosity (μ₀):

λ₀=κ₀/μ₀

The effective permeability characterizes the ability of the crude oil to flow through the rock material of the reservoir. As will be evident from the above-mentioned Darcy's Law, permeability should be affected by pressure in the rock material. The millidarcy unit mentioned above in connection with the typical unit used for permeability (κ) is related to the basic unit of permeability measure, m² in the mks system. The darcy is referenced to a mixture of unit systems. A medium with a permeability of 1 darcy permits a flow of 1 cm³/s of a fluid with viscosity 1 cP (1 mPa·s) under a pressure gradient of 1 atm/cm acting across an area of 1 cm². A millidarcy (md) is equal to 0.001 darcy. Rock permeability is usually expressed in millidarcys (md) because rocks hosting hydrocarbon or water accumulations typically exhibit permeability ranging from 5 to 2000 md.

Thus, the principle used herein is that heat applied to a reservoir increases its permeability and reduces the viscosity of the crude oil to increase the oil mobility. In other words, lowering oil viscosity with heat increases the flow rate of the oil. Conventional heating methods include cyclic steam injection, steam flooding and fire flooding. For cyclic steam injection, steam may first be injected into a well for a few days or weeks. Then the heat is allowed to dissipate into the reservoir for a few days to reduce oil viscosity. Finally, the production begins with improved flow rate. The three step process is then repeated e.g. after the flow rate diminishes. In steam flooding some wells are used for injecting steam and others for oil production. The steam flood acts to both heat the reservoir and push the oil by displacement toward the production wells. In many cases gravity is also used to move the oil toward the production well. Fire flooding is where combustion generates heat within the reservoir itself.

TABLE 1 Composition by Weight Melting or Liquification Hydrocarbon Average Range Point Paraffins 30% 15 to 60% 115° F. to 155° F. (46° C. to 68° C.) Naphthenes 49% 30 to 60% Aromatics 15%  3 to 30% Asphaltenes  6% Remainder 180° F. (82° C.) Karogen 842° F. to 932° F. (450° C. to 500° C.) It should be realized that the viscosity is affected by temperature, pressure, and by composition. Among others, the following conditions impact oil flow rate: 1) Crude oils contain substantial proportions of saturated and aromatic hydrocarbons with relatively small percentages of resins and asphaltenes and other substances as listed in Table 1. More degraded crude oils contain substantially larger proportions of resins and asphaltenes. Heavy crude oil (API<22) occurs when the oil contains paraffin and/or asphaltenes and the temperature of the oil reservoir is too low. See Table 1 above for melting or liquification points and see also FIG. 1a . As oil is heated the viscosity lowers and the efficiencies of flow increase. 2) Crude oil (including light crude oil API>30) viscosity increases as it cools due to one or more of the following conditions:

-   -   a) the oil reservoir is shallow and the temperature of the         reservoir is low;     -   b) it is heavy crude oil (API<22);     -   c) the oil reservoir is deep and the oil cools as it is pumped         out of the well;     -   d) the ambient temperature is extremely cold and the oil cools         quickly as it is exposed to the cold near or at the surface; and     -   e) any set of conditions where the oil cools and the viscosity         increases and this adversely effects the efficiency of the oil         flow in a production well.

As will be appreciated from the foregoing, heating the reservoir to remove barriers to the flow of fluids into a well will tend to lower the viscosity of the fluids so that the existing permeability will allow the oil to flow with an increased rate and hence increased volume to the production wells. An important teaching hereof is to burn crude oil or natural gas extracted from an underground reservoir (or burn both crude oil and natural gas extracted from the underground reservoir), in order to provide thermal energy. In other words, the teaching is to supply the necessary power and materials from the reservoir itself to mobilize the oil and move it to the production wells. A heat source fed by fuel produced from the reservoir accomplishes the production of heat. It does so in such a way, as shown below, as to allow enhanced oil recovery that is environmentally benign.

A gas flare, alternatively known as a flare stack, is a gas combustion device used in industrial plants such as petroleum refineries, chemical plants, and natural gas processing plants as well as at oil or gas production sites having oil wells, gas wells, offshore oil and gas rigs and landfills. When petroleum crude oil is extracted and produced from onshore or offshore oil wells, raw natural gas associated with the oil is produced to the surface as well. In areas of the world lacking pipelines and other gas transportation infrastructure, vast amounts of such associated gas are commonly flared as waste or unusable gas. The flaring of associated gas may occur at the top of a vertical flare stack or it may occur in a ground-level flare in an earthen pit.

Every year, billions of dollars' worth of natural gas goes up in smoke, as companies burn off gas released during oil production—a common practice known as gas flaring. The amount of natural gas being flared and vented annually is astronomical. It is equivalent to 25 percent of the United States' annual gas consumption, 30 percent of the European Union's annual gas consumption, 75 percent of Russia's annual gas exports, and more than the combined gas consumption of Central and South America. In Africa alone, the annual amount of gas flared is equivalent to half the continent's power consumption.

Gas flaring has a global impact on climate change by producing about 400 million tons of greenhouse gas emissions annually. Residents in communities near gas flaring have experienced chronic health problems, including bronchial, chest, rheumatic, and eye problems.

A typical oil production well design is illustrated in FIG. 2. This well design includes typically casing 11, which is usually made out of cement and a steel pipe. Casing 11 is installed to secure bore integrity and to separate the well bore from the environment. Casing 11 protects the aquifer from contamination. A standard fill 12 is also provided. Two examples of fill 12 are treated water and diesel fuel. Currently, the fills 12 used in the art are not good insulators. A seal (or plug) 13 is placed at the bottom of the well, at the beginning of the oil reservoir pay zone (i.e., the top of the reservoir) so that a seal is established separating the bore from the oil collection zone (i.e., oil reservoir). The casing 11 includes perforations 14 from the seal 13 to the bottom of the well to allow the oil to enter the cased area. An oil production pipe 15 is installed after the well is drilled and after the casing 11 is perforated 14. The seal 13 is installed after the oil production pipe 15 is installed. The oil production pipe 15 is the transport mechanism for delivering the oil to the surface. One or more pumps 16 a, 16 b can also be provided. In this example, there is a submersible pump 16 a and a surface pump 16 b. The pumps 16 a, 16 b pump the oil entering the well through the perforations 14 up to the surface. The efficiency of the pumps 16 a, 16 b correlate to the viscosity of the oil. The lower the viscosity of the oils, the more barrels can be pumped per day. The width of the reservoir 17 (or pay zone), the saturation of the oil, the permeability of the rock, the porosity of the reservoir 17 and the viscosity of the oil determine the rate of extraction and the amount of oil 10 that can be harvested from the reservoir 17.

SUMMARY OF THE INVENTION

The present invention provides a solution to the aforementioned problems and changes the high viscosity oil to a lower viscosity oil by providing thermally assisted oil production wells using thermal methods based on geothermal well-generated heat and/or flaring gas, and eliminates or reduces the environmental impact of flaring gas or burning fossil fuels in land based and offshore-based crude oil production wells.

The invention can be used for light crude oil, heavy crude oil, extra heavy crude oil, bitumen, tar sands, oil sands and shale oil.

According to a first aspect of the invention, a system for recovering oil, gas or oil and gas from a reservoir beneath a surface is provided. The system includes at least one production pipe for receiving the oil and gas in the reservoir, at least one pump configured to pump the oil and gas to the surface, a casing surrounding the at least one production pipe, and at least one heating element in parallel with the production pipe configured to provide heat to the oil and gas being pumped to the surface.

According to a first embodiment of the first aspect of the invention, the at least one heating element comprises one or more electric heating cables. The one or more electric heating cables can be positioned in a fluid heating chamber within the casing and surrounding the at least one production pipe. The one or more electric heating cables radiate heat to the fluid heating chamber for heating the oil and gas being pumped to the surface in the at least one production pipe. According to another embodiment, the one or more electric heating cables can extend into a heating cocoon surrounding a portion of the casing. In this embodiment, the reservoir can be underwater and the portion of the casing surrounded by the heating cocoon is underwater, such that the heating cocoon heats the water surrounding the casing and the at least one production pipe.

According further to the first embodiment of the first aspect of the invention, the at least one pump is configured to pump brine or water from the reservoir to the surface, and provide pumped oil, gas and brine to a separator configured to separate oil, gas and brine. A portion of the separated oil, gas or oil and gas is provided to an electricity generator to fuel the electricity generator. This portion of the separated oil, gas or oil and gas can include flared gas. The electricity generator provides electricity to the one or more electric heating cables. The generation of electricity by the electricity generator further creates an exhaust gas, and the exhaust gas can be mixed with the separated brine to create a mixture of gas and brine that is injected into the reservoir to increase the flow of oil and gas in the reservoir to the at least one production pipe. The mixture of gas and brine can be injected into a perforated pipe positioned in the reservoir beneath the casing.

According to a second embodiment of the first aspect of the invention, the at least one heating element comprises one or more heating pipes transporting a heating substance. The one or more heating pipes can be arranged in a fluid heating chamber within the casing and surrounding the at least one production pipe. The one or more heating pipes include perforations and provide heat to the fluid heating chamber for heating the oil and gas being pumped to the surface in the at least one production pipe. In an alternate embodiment, the one or more heating pipes extend into a heating cocoon surrounding a portion of the casing. In a further alternate embodiment, the one or more heating pipes include at least one heating pipe within the at least one production pipe.

According further to the second embodiment of the first aspect of the invention, the at least one pump is further configured to pump brine or water from the reservoir to the surface, and provide pumped oil, gas and brine to a separator configured to separate oil, gas and brine. A portion of the separated oil, gas or oil and gas is provided to a heating source configured to heat a fluid. This portion of the separated oil, gas or oil and gas can include flared gas. In one embodiment, the heat source is a boiler configured to heat a fluid, and it creates an exhaust gas in the process. The exhaust gas can be mixed with the separated brine by a heat exchanger and mixer to create a mixture of gas and brine that can injected into the reservoir through the one or more heating pipes to increase the flow of oil and gas in the reservoir to the at least one production pipe. In an embodiment, the mixture of gas and brine is injected into a perforated pipe positioned in the reservoir beneath the casing. The system may further include a plurality of horizontal bore holes in the reservoir, and the one or more heating pipes extend into the plurality of horizontal bore holes.

According to a second aspect of the invention, a method for recovering oil, gas or oil and gas from a reservoir beneath a surface is provided. The method includes providing at least one production pipe for receiving the oil and gas in the reservoir and a casing surrounding the at least one production pipe, pumping oil and gas to the surface with at least one pump; and heating the oil and gas being pumped to the surface with at least one heating element in parallel with the production pipe.

According to a first embodiment of the second aspect of the invention, the at least one heating element comprises one or more electric heating cables. The one or more electric heating cables are in a fluid heating chamber within the casing and surrounding the at least one production pipe, and the one or more electric heating cables radiate heat to the fluid heating chamber for heating the oil and gas being pumped to the surface in the at least one production pipe. The one or more electric heating cables radiate heat to the fluid heating chamber for heating the oil and gas being pumped to the surface in the at least one production pipe. According to another embodiment, the one or more electric heating cables can extend into a heating cocoon surrounding a portion of the casing. In this embodiment, the reservoir can be underwater and the portion of the casing surrounded by the heating cocoon is underwater, such that the heating cocoon heats the water surrounding the casing and the at least one production pipe.

According further to the first embodiment of a method according to the invention, the method further comprises pumping brine or water from the reservoir to the surface by the at least one pump together with the pumped oil and gas, providing the pumped oil, gas and brine to a separator, and separating the oil, gas and brine. The method further comprises providing a portion of the separated oil, gas or oil and gas to an electricity generator to fuel the electricity generator. The portion of the separated oil, gas or oil and gas can include flared gas. According further to the embodiment, the method further comprises generating electricity by the electricity generator and providing electricity to the one or more electric heating cables. The generation of electricity by the electricity generator creates an exhaust gas, and the method further comprises mixing the exhaust gas with the separated brine to create a mixture of gas and brine and injecting the mixture into the reservoir to increase the flow of oil and gas in the reservoir to the at least one production pipe. The mixture of gas and brine is injected into a perforated pipe positioned in the reservoir beneath the casing.

According to a second embodiment of the second aspect of the invention, the at least one heating element comprises one or more heating pipes. The one or more heating pipes can be in a fluid heating chamber within the casing and surrounding the at least one production pipe, and the one or more heating pipes comprise perforations and provide heat to the fluid heating chamber for heating the oil and gas being pumped to the surface in the at least one production pipe. In an alternative embodiment, the one or more heating pipes extend into a heating cocoon surrounding a portion of the casing. In a further alternative embodiment, the one or more heating pipes include at least one heating pipe within the at least one production pipe.

According further to the second embodiment of the second aspect of the invention, the method further comprises pumping brine or water in the reservoir to the surface by the at least one pump together with the pumped oil and gas, providing the pumped oil, gas and brine to a separator, and separating the oil, gas and brine. The method further comprises providing a portion of the separated oil, gas or oil and gas to a heating source configured to heat a fluid. A portion of the separated oil, gas or oil and gas can include flared gas. In one embodiment, the heat source is a boiler configured to heat a fluid. The heat source creates an exhaust gas, and the method further comprises mixing the exhaust gas with the separated brine to create a mixture of gas and brine and injecting the mixture into the reservoir to increase the flow of oil, gas or oil and gas in the reservoir to the at least one production pipe. The mixture of gas and brine is injected into a perforated pipe positioned in the reservoir beneath the casing. The method can further comprise providing a plurality of horizontal bore holes in the reservoir, and extending the one or more heating pipes into the plurality of horizontal bore holes.

BRIEF DESCRIPTION OF THE FIGURES

FIGS. 1a-1d show examples of how heating oil lowers its viscosity.

FIG. 2 shows a production well according to the prior art.

FIG. 3 shows an embodiment of a thermally assisted well with hot exhaust gas mixed with brine separated from an oil/gas/brine mixture extracted from an oil reservoir and injected back into the reservoir according to the teachings hereof.

FIG. 4 shows an embodiment of a thermally assisted well according to the teachings hereof with hot exhaust gas mixed in the heat exchanger with brine separated from an oil/gas/brine mixture extracted from an oil reservoir and injected back into the reservoir via the heating pipes and horizontal bore holes.

FIG. 5 shows an embodiment of a thermally assisted well with hot exhaust gas mixed with brine separated from an oil/gas/brine mixture extracted from an oil reservoir and injected back into the reservoir according to the teachings hereof.

FIG. 6 shows an enhanced oil recovery system with thermal flooding radiating heat in an embodiment according to the teachings hereof.

FIG. 7 shows a variation of the embodiment of FIG. 6, in which the loops of FIG. 7 work the same as shown in FIG. 6, except a new thermally assisted production well is drilled for example as shown to replace the normal prior art production well of FIG. 2.

FIG. 8 shows a thermally assisted well implementation for an offshore platform, wherein the heat source is a “Single Well Engineered Geothermal System” (or “SWEGS”) and/or the burning and scrubbing of gas according to the teachings hereof so that the gas that is usually flared is not wasted.

FIG. 9 shows a thermally assisted well off-shore implementation with additional brine being pumped from the ocean, as may be required, to maximize the brine/CO₂ flooding according to the teachings hereof.

FIG. 10a shows a heat source including a “Green Boiler” with a heat exchanger and a hot water manifold (and/or other heat source) according to the teachings hereof.

FIG. 10b shows a hot water manifold connected to a plurality of heat sources in a “Green Boiler” system according to the teachings hereof.

FIG. 11 shows an embodiment of enhanced oil production by thermal methods according to the teachings hereof.

FIG. 12 shows another embodiment of enhanced oil production by thermal methods according to the teachings hereof.

FIG. 13 shows another embodiment of enhanced oil production by thermal methods according to the teachings hereof.

FIG. 14 shows a land based oil production well modified for thermal heating with electric heating cables.

FIG. 15 shows an off shore platform based oil production well modified for thermal heating with electric cables.

FIG. 16 shows a retrofit heating cocoon that wraps around the under-ocean portion of the oil well and that utilizes electric resistive heating cables to heat fluid fill in a heating chamber that surrounds an oil production pipe.

DETAILED DESCRIPTION OF THE FIGURES

According to a first embodiment of the invention shown in FIG. 3, an improved well 100 a is provided that solves the problem of an oil well where the crude oil reservoir is at a high temperature (e.g., above 180° F.) and the oil flow temperature decreases as it flows out of the well, thereby raising the viscosity of the oil, or an oil reservoir where the oil is at a high viscosity and the reservoir temperature is below 180° F. The oil cools as it is pumped to the surface causing the viscosity to increase, thereby lowering the efficiency of flow and the barrels yielded per day, or the oil flows more slowly out of the reservoir because it has a higher viscosity.

The well 100 a heats the oil in the reservoir 107 and in the oil production pipes 105 so that the viscosity of the oil is always at a point where the oil flows more efficiently. This is accomplished by using geothermally generated heat and/or by burning the flaring gas or other fuels and using the heat generated from the burning fuels. The exhaust from the burning flaring gas or fuel is injected back into the well by mixing it with the separated brine using an injection well drilled for this purpose.

The advantages of this method are delivering heat to the reservoir 107 while also delivering CO₂, a byproduct of burning the flaring gas or other fuels in a boiler to the reservoir. The injection provides the benefits of water flooding, thermal flooding and CO₂ flooding.

As the well 100 a is drilled, a casing 101 is installed. This casing 101 is generally waterproof or can be waterproofed and is insulated. Heating chamber 102 forms a cocoon of heat that surrounds the oil production pipe 105 and isolates and heats the extracting oil keeping it at a low viscosity or lowering its viscosity. The heating chamber 102 is part of a closed loop system that continuously heats the extracting oil. A seal (or plug) 103 is positioned at the bottom of the well at the beginning of the oil reservoir pay zone (i.e., top of the oil reservoir 107), so that a water proof seal is established separating the bore from the oil collection zone (i.e., oil reservoir 107). This seal forms the bottom of the heating chamber 102. The casing 101 is perforated 104 from the seal 103 to the bottom of the well 100 a to allow the oil to enter the cased area. An oil production pipe 105 is installed after the well 100 a is drilled and after the casing 101 is perforated 104. The seal 103 is installed after the oil production pipe 105 is installed. The oil production pipe 105 is the transport mechanism for delivering the oil to the surface.

A submersible pump 106 a and/or a pump 106 b on the surface, pump the oil entering the well 100 a through the perforations 104 up to the surface. The efficiency of the pump 106 a, 106 b correlates to the viscosity of the oil. More barrels of oil can be pumped on a per day basis when the viscosity of the oil is lowered. The width of the reserve (pay zone), the saturation of the oil, the permeability of the rock and the viscosity of the oil determine the rate of extraction and the amount of oil that can be harvested form the reservoir 107.

Hot water is pumped through one or more heating pipes 108 into the heating chamber 102. To prevent the hot liquid water from vaporizing into steam, the injected water is pressurized. The heating pipe 108 has specially drilled holes, called heating jets 109, drilled at strategic locations to heat the chamber 102 at various depths. The size and placement of the heating jets 109 has to allow the heat of the water to compensate for the loss of heat of the extracting oil at that position in the well 100 a. The heating pipes 108 are installed by drilling through the top of the casing 101 and welding the pipes 108 to the casing 101 or to additional reinforced steel piping that would be installed.

As the oil, gas and brine is extracted from the well the oil, gas and brine 120 goes through a separation system 110 that separates the oil 114, the gas 115 and the brine 116. The separated oil 114 can be shipped to a processing destination. The separated gas 115 is burned and the exhaust 118, mostly comprised of CO₂, is merged with the brine 116. The separated brine 116 mixed with the gas exhaust 118 by a heat exchanger/mixer 117 and the mixture 119 is injected into the reservoir 107 in one or more injection wells to maintain reservoir pressure. The CO₂ and hot brine mixture 119 interacts with the oil lowering its viscosity.

Hot water is delivered from a heating source 111 into the heating chamber 102 on a continuous basis, and returned to the heating source 111 for re-heating. A heat delivery pipe 112 is a small manifold that supplies several heating pipes 108 with hot water from the heating source 111. After the hot water in the heating chamber 102 delivers heat to the extracting oil, it is returned to the heating source 111 via a heating source return pipe 113 to be reheated in a closed loop system.

A second embodiment of a thermally assisted oil production well, and a variation thereof, are shown in FIGS. 4 and 5. The second embodiment addresses the problem new or existing oil wells where the crude oil reservoir temperature is below the melting point of paraffin or the liquidation point of asphaltenes. In such a well, the oil flow temperature decreases as it flows out of the well and raises the already high viscosity of the oil. The oil cools as it is pumped to the surface causing the viscosity to increase thereby lowering the efficiency of flow and the barrels per day.

The wells 100 b, 100 c shown in FIGS. 4 and 5 heat the oil in the oil reservoir 107 and in the oil production pipe 105 so that the viscosity of the oil is always at a point where the oil efficiently flows. The wells 100 b, 100 c also add CO₂ to the oil reservoir 107, which also lowers the viscosity of the oil.

As described with respect to the well 100 a of FIG. 3, a casing 101 is installed. The casing 101 should be insulated. Heating chamber 102 forms a cocoon of heat that surrounds the oil production pipe 105, isolating and heating the extracting oil. The heating chamber 102 is part of a closed loop system that continuously heats the extracting oil. A seal (or plug) 103 is positioned at the bottom of the well at the beginning of the oil reservoir pay zone so that a water proof seal is established separating the bore from the oil collection zone. This seal 103 forms the bottom of the heating chamber 102. A second seal 103 can be implemented at the bottom of casing 101. The casing 101 is perforated 104 from the seal 103 to the bottom of the well 100 b to allow the oil to enter the cased area. An oil production pipe 105 is installed after the well 100 b is drilled and after the casing 101 is perforated 104. The seal 103 is installed after the oil production pipe 105 is installed. The oil production pipe 105 is the transport mechanism for delivering the oil to the surface.

A submersible pump 106 a and/or a pump 106 b on the surface, pump the oil entering the well 100 b through the perforations 104 up to the surface. Hot and pressurized liquid water is pumped through one or more heating pipes 108 into the heating chamber 102. In contrast to the well 100 a shown in FIG. 2, the heating pipes 108 are installed on the outside of oil production pipe 105 with the submersible pump 106 a. The heating pipes 108 radiate heat 122 into the oil production pipe 105 and the heating chamber 102. The heating chamber 102 also helps keep the oil production pipe 105 hot so it will not allow the oil to cool and increase its viscosity.

The heating pipes 108 are extended deeper into the oil reservoir 107 by drilling horizontal bores to allow the hot brine or oil to penetrate the oil reservoir 107. The placement of the horizontal bores with the heat pipes 108 installed is modeled to maximize the heating of the reservoir 107. The reservoir heating jets 121 are drilled into the bottom of the heating pipe 108 at one or more locations. Heated brine 116 with the combined exhaust (CO₂) 118 from burning flaring gas is pumped into the oil reservoir 107, heating the extractable oil and lowering its viscosity. A toroidal convection can be established which will increase the spread of heat and increase the flow of oil. When the reservoir heating jets 121 are installed, the performance can be increased by drilling the horizontal bore holes to spread the heated brine 116 and CO₂ 118 into the reservoir 107. The horizontal bore holes can have a slotted liner. The reservoir heating jets 121 can be extended into the horizontal bore holes.

As the oil, gas and brine is extracted from the well the oil, gas and brine 120 goes through a separation system 110 that separates the oil 114, the gas 115 and the brine 116. The separated oil 114 can be shipped to a processing destination. Hot water is delivered from a heating source 111 into the heating chamber 102 on a continuous basis, and returned to the heating source 111 for re-heating.

In the well 100 c shown in FIG. 5, the perforations are modified to add horizontal bores 123, which are drilled to improve the collection of the oil. These bore holes 123 can have slotted liners, which can adjust the size of the bore holes 123.

The larger the heating pipes 108 are the more heat can be delivered to the oil reservoir 107. Maximizing the heat delivered to the oil reservoir 107 creates a larger change in the oil viscosity and increase the amount of oil that can be extracted. Heating the oil and adding CO₂ in the reservoir 107 lowers oil viscosity, changes surface tensions, heats the oil to release gas that pressurizes the oil capsules and creates convection in the reservoir 107 that helps spread the heat.

A third embodiment of a thermally assisted oil production well, and a variation thereof, are shown in FIGS. 6 and 7. This embodiment can be used in connection with a geothermal heat generating well system and/or a boiler that burns gas that is usually flared, or another fuel, where the CO₂ laden exhaust is used to CO₂ flood the reservoir. Examples of such well systems can be found described in applicant's U.S. Pat. No. 8,616,000 titled “System and method of capturing geothermal heat from within a drilled well to generate electricity” and International Patent Application No. PCT/US2015/031486 filed May 19, 2015, titled “Green Boiler—Closed Loop Energy and Power System to Support Enhanced Oil Recovery That Is Environmentally Friendly”. The reservoir is also heat flooded and brine flooded. The combined flooding lowers the viscosity of the oil and improves the oil flow.

According to an embodiment shown in FIG. 6, which incorporates a typical production well 215, a heat exchanger 207 picks up heat from the geothermal well 201 having pumps and valves 201 a. A closed loop in the geothermal well 201 brings heated water to the surface where it is provided to a boiler 202, which augments the extracted heat. In some cases where flaring gas 205 is plentiful, it is possible that no geothermal well 201 is needed for the boiler 202 to supply all of the necessary heat to the system.

Hot water 204 from the boiler 202 is distributed and pumped to heat delivery wells 203. Heated water 204 transfers heat to oil reservoir 214 heating the oil 212 and lowering the oil viscosity. Cooled water is returned to the geothermal well 201 and/or the boiler 202 for re-heating. The exhaust gas 209 (CO₂) from the boiler 202 is sent to the heat exchanger/mixer 207 for mixing with the brine 208 to create a mixture 206 of brine and CO₂. The cooled water from the heat exchanger 207 is returned to the geothermal well 201 and/or the boiler 202 for re-heating.

A second loop is provided in addition to the loop described above. Oil and brine flows through slotted liners and is pumped to surface by a submersible pump of the production wells 215. Brine 208 and gas 205, usually flared gas, are separated from oil 210.

The flared gas 205 is sent to the boiler 202 for burning. Separated brine 208 from the oil production wells 215 is heated and combined with exhausted gas 209 by the heat exchanger/mixer 207 and pumped back into the reservoir 214 as a mixture 206, for flooding 211 the reservoir 214 as previously described. Replaced heated water and heat expansion maintains reservoir pressure.

A variation on this embodiment is shown in FIG. 7. The system works similar to that described in reference to FIG. 6, however, a thermally assisted oil production well 100 c is drilled to replace the production wells 215 and the brine flooding wells shown in FIG. 6. In the example of FIG. 7, the thermally assisted oil production well 100 c is the well 100 c shown and described above in reference to FIG. 5, but a different thermally assisted oil production well 100 could also be incorporated.

Additional embodiments for incorporating a thermally assisted oil production well with an offshore oil reservoir are shown in FIGS. 8 and 9.

As shown in FIG. 8, a thermally assisted oil production well 100 a, such as the well shown in FIG. 3, is provided for platform 307 in connection with an underwater oil reservoir 309. FIG. 8 shows an embodiment for a retrofitted well 100 a with a heavy, medium or light crude oil reservoir 307. Oil, brine and gas pumped from the reservoir 309, collectively identified with reference numeral 303, are provided to a separator 304. Separated oil 305 is provided from the separator 304 for storage and further use. Gas 302, which can be flaring gas, is provided to a boiler 308 for burning and scrubbing, and the exhaust 301 is combined with separated brine 306 to create a brine and CO₂ mixture 307 that can be flooded into the reservoir 309. The boiler 308 may further act as a heat source, similar to heat source 111 in FIGS. 3-5, which receives cooled water from the well 100 a, heats the water and returns it for use with the well 100 a. In one embodiment, the heated water can be used by an electrical generator 310 to generate electricity, which is supplied to electric heating cables running down the well 100 a, or the electrical generator 321 can be used to further heat the brine for supplying to the well 100 a.

As shown in FIG. 9, a thermally assisted oil production well 100 c, such as the well 100 c shown in FIG. 5, is provided for platform 320 in connection with an underwater oil reservoir 319. FIG. 9 shows an embodiment for a new well 100 c with a heavy, medium or light crude oil reservoir 319. Oil, brine and gas pumped from the reservoir 319, collectively identified with reference numeral 313, are provided to a separator 314. Separated oil 315 is provided from the separator 314 for storage and further use. Gas 312, which can be flaring gas, is provided to a boiler 318 for burning and scrubbing, and the exhaust 316 is combined with brine, which can be separated brine from the separator 313, brine heated by the boiler 318 or additional brine 311 pumped from the ocean or water body to create a brine and CO₂ mixture 317 that can be flooded into the reservoir 319. In one embodiment, the heated water can be used by an electrical generator 321 to generate electricity, which is supplied to electric heating cables running down the well 100 c, or the electrical generator 321 can be used to further heat the brine for supplying to the well 100 c.

Further embodiments of the invention are shown in FIGS. 10a and 10b , wherein flaring gas is used as a heat source. The benefits of using flaring gas as a heat source include using heat that is currently being wasted to augment or supply other enhanced oil recovery methods that require heat generation and to reduce or replace current electrical generation for land based operations and offshore platforms. Using flaring gas as a heat source, one further can reduce and/or eliminate the environmental impact of flaring gas. This is achieved, for example, by complete burning of the flaring gas under a controlled environment, scrubbing the flaring gas exhaust, injecting the hot exhaust back into the reservoir (i.e., CO₂ flooding) and reducing other fossil fuel use by generating electricity. Many of these techniques have been described herein. Using flaring gas a heat source further provides financial benefits, such as creating carbon credits, reducing or eliminating electric generation fuel costs, and recouping the investment of setting up the operation.

The heat source system shown in FIG. 10a is comprised of three or more components used individually or in combination. One or more geothermal well 401, such as the geothermal well described in reference to FIGS. 4-5, are drilled into the earth until the required temperature is encountered in an area referred to as a heat reservoir 410. For example, the well 401 may have a diameter of 17.5 inches (0.45 meters) drilled into a region of hot rock. The well 401 may include lateral bore holes 407 drilled into the rock which are installed with heat pipes 408 to harvest heat and deliver it to the central well. A heat exchanger 409 transfers the heat from the heat pipes 408 to the closed cycle system 404. The heat is then pumped to the surface using a pump 402, and delivered to the production well. Insulation 403, 406 and a high heat conductive material 405 are provided in the well to minimize heat loss. The heat delivered is based on the heat resource encountered in the earth. If enough heat is encountered the operational cost of the heat source is minimized because no fossil fuel is burned to generate the required amount of heat to change the oil viscosity. The geothermal well 401 can be depreciated over a long period of time and thus the operational costs are composed of running the pumps. Geothermal well 401 can be used alone or in combination with a boiler 412 and waste heat 413 to provide the required thermal energy.

A boiler 412 can be used to augment the geothermal well 401 or replace the geothermal well 401 for the heat required. The boiler 412, when used to burn gas 416 that is usually released or flared, has a low cost as it uses heat that is normally wasted. The boiler 412 can also burn fossil fuel and/or crude oil. When the boiler 412 burns gas 416 from the oil extraction, the exhaust is scrubbed by an exhaust scrubber 414 and the exhaust 417 is mixed with brine by a mixer 415 for injection into an oil reservoir. There is therefore an enormous reduction in the negative environmental impact of the flaring of the gas. Flaring gas is estimated to be responsible for over 30% of the world's carbon pollution.

Additionally, if an additional heat source 413, such as waste heat or electrical resistant heat, is available, the other heat source 413 can be used to supply additional heat. For example, on an offshore oil platform where it would be more difficult to implement a geothermal well, waste heat or a combination of waste heat, electrical heat and/or a boiler can be used to supply the heat source for heating and/or flooding the oil reservoir. As shown in FIG. 10a , the other heat source 413 supplies heat to a manifold 418, such as a hot water manifold, which further heats water, and supplies it to a heat exchanger/mixer 415, which provides a similar function as heat exchanger/mixers described previously such as heat exchanger/mixer 117 and 207 for example.

An embodiment of a further system according to the invention is shown in FIG. 10b , wherein the thermal energy provided by a heat source will be able to support multiple production wells. The amount of heat required by each production well is dependent on the characteristics of the oil and the oil reservoir. The thermal energy can be transported directly to the wells 500 or transferred to another heat carrying fluid with a heat exchanger 508.

As shown in FIG. 10b , one or more oil wells 500 provide oil, gas and brine to one or more separators 515, which separates the oil 502, gas 501 a and brine 503. The separated gas 501 a is provided to a manifold 516, which supplies the gas 501 b to boilers 504, such as the boilers previously described herein. Heated gas from the boilers 504 is supplied to an exhaust scrubber 505. From the exhaust scrubber 505, the resulting scrubbed exhaust gas and CO₂ are provided to a heat exchanger/mixer 510, where the thermal energy from the heated exhaust can be transferred to another heat transport fluid, such as the separated brine 503. The mixture 510 of the heated brine, exhaust and CO₂ can be provided back to the reservoir. Heated water from the boiler 504 is further provided to a hot water manifold 506, which supplies the heated water to the heat exchanger/mixer 508 and to other applications 512 requiring heat, such as HVAC, electricity generation, etc. The hot water manifold 506 also receives heat from other heat sources 514. Cooled water 511 from the heat exchanger/mixer 508 from after the transfer of thermal energy referenced above can be supplied back to the boilers 504 for reheating.

According further to the inventions, embodiments of thermally assisted wells are provided, which in contrast to the wells 100 a-100 c of FIGS. 3-5, do not utilize hot exhaust gas from a heat sources such as a boiler. Such embodiments are shown in FIGS. 11-13.

FIG. 11 shows a thermally assisted production well 600 a, which addresses a problem associated with currently existing deep oil well where the crude oil reservoir is at a high temperature (above 200° F.) and the oil flow temperature decreases as it flows out of the well, raising the viscosity of the oil. As explained previously, the cooling of the oil and corresponding increase in viscosity has a negative impact on the efficiency of oil recovery.

The thermally assisted well 600 a of FIG. 11 heats the oil in a reservoir 607 so that the viscosity of the oil is always at a point where the oil efficiently flows.

The well 600 a comprises a casing 601, which can be in an embodiment, cement and a steel pipe. The casing 601 should be insulated to reduce heat loss. The fill 602 is also provided, which in many instances is already present in a production well. Examples of a fill 602 include treated water or diesel fuel. One or more seals (or plugs) 603 are provided at the bottom of the well 600 a at the beginning of the oil reservoir 607 pay zone (i.e., the top of the oil reservoir 607) to establish a seal separating the bore from the oil collection zone (i.e., the oil reservoir 607). The casing 601 further includes perforations 604 from the seal 603 to the bottom of the well 600 a to allow the oil to enter the cased area. An oil production pipe 605 is preferably installed after the well is drilled and after the casing 601 is perforated 604. The seal 603 is preferably installed after the oil production pipe 605 is installed. The oil production pipe 605 is the transport mechanism for delivering the oil to the surface. If the oil production pipe 605 can be insulated, it will decrease the loss of heat and improve the viscosity of the oil being transferred through the oil production pipe 605 from the oil reservoir 607.

A submersible pump 606 a and/or a surface pump 606 b pump the oil that is entering the well 600 a through the perforations 604 up to the surface. The efficiency of the pumps 606 a, 606 b correlates to the low viscosity of the oil. The submersible pump 606 a is located lower in the well 600 a also pumps the oil and is effected by the viscosity of the oil.

The width of the reservoir 607, the saturation of the oil, the permeability of the rock, the porosity of the reservoir 607 and the viscosity of the oil determine the rate of extraction and the amount of oil that can be harvested form the reservoir 607.

Oil and/or brine 612 that has been extracted and heated by a heat exchanger 613 is injected into the well 600 a through a heating pipe 608 that is installed inside the oil production pipe 605. The oil production pipe 605 has specially drilled holes, called heating jets 609, drilled at strategic locations to heat the oil being extracted at various points in the oil production pipe 605. The size and placement of these jets 609 allows the heat of the injected oil or brine to compensate for the loss of heat of the extracting oil at that position in the well 600 a. The brine from heating jets 609 raises the temperature of the extracting fluid in the reservoir 607.

As the oil and brine are extracted from the well 600 a, the oil and brine go through a separator 610 that separates the oil 614 from the brine 615. The separated oil 614 can be shipped to a processing destination. The separated brine 615 is usually injected into the reservoir 607 to maintain reservoir pressure or it is shipped to a disposal injection well. If the oil and/or brine 612 are used as the heat delivery fluid the injection volumes are removed from the separator 610. Heat is delivered from a heat source 611, such as a boiler, into the heat exchanger 613. The small portion of the brine and/or oil 612 from the separator 610 is heated by the heat exchanger 613 and injected back into the well 600 a by way of the heat pipe 608, to merge with the cooling extracted oil to re-heat the oil and maintain the oil's low viscosity as it rises through the oil production pipe 605.

A further embodiment of a thermally assisted oil production well without using exhaust gas, and a variation thereof, are shown in FIGS. 12 and 13. This embodiment addresses the problem of new or existing oil wells where the crude oil reservoir temperature is below the melting point of paraffin or the liquidation point of asphaltenes. In such a well, the oil flow temperature decreases as it flows out of the well and raises the already high viscosity of the oil. The oil cools as it is pumped to the surface causing the viscosity to increase thereby lowering the efficiency of flow and the barrels per day.

The wells 600 b, 600 c shown in FIGS. 12 and 13 heat the oil in the oil reservoir 607 and in the oil production pipe 605 so that the viscosity of the oil is always at a point where the oil efficiently flows. The wells 600 b, 600 c also add CO₂ to the oil reservoir 607, which also lowers the viscosity of the oil.

As described with respect to well 600 a of FIG. 11, the well 600 b comprises a casing 601, which can be in an embodiment, cement and a steel pipe. The casing 601 should be insulated to reduce heat loss. The fill 602 is also provided. In the well 600 b, two seals (or plugs) 603 are provided at the bottom of the well 600 a at the beginning of the oil reservoir 607 pay zone (i.e., the top of the oil reservoir 607) to establish a seal separating the bore from the oil collection zone (i.e., the oil reservoir 607), and at the bottom of the casing 601. The casing 601 further includes perforations 604 from the seal 603 to the bottom of the well 600 a to allow the oil to enter the cased area. An oil production pipe 605 is preferably installed after the well is drilled and after the casing 601 is perforated 604. The seal 603 is preferably installed after the oil production pipe 605 is installed. The oil production pipe 605 is the transport mechanism for delivering the oil to the surface. If the oil production pipe 605 can be insulated, it will decrease the loss of heat and improve the viscosity of the oil being transferred through the oil production pipe 605 from the oil reservoir 607.

A surface pump 606 b pumps the oil that is entering the well 600 b through the perforations 604 up to the surface. The efficiency of the pumps 606 a, 606 b correlates to the low viscosity of the oil. The submersible pump 606 b is located lower in the well 600 a also pumps the oil and is effected by the viscosity of the oil.

Oil and/or brine 612 that has been extracted and heated by a heat exchanger 613 is injected into the well 600 a through a heating pipe 608 that is installed inside the oil production pipe 605. The oil production pipe 605 heating jets 609 drilled at strategic locations to heat the oil being extracted at various points in the oil production pipe 605. The brine from the heating jets 609 raises the temperature of the extracting fluid in the reservoir 607. As the oil and brine are extracted from the well 600 b, the oil and brine go through a separator 610 that separates the oil 614 from the brine 615. The separated oil 614 can be shipped to a processing destination. The separated brine 615 is usually injected into the reservoir to maintain reservoir pressure or it is shipped to a disposal injection well. If the oil and/or brine 612 are used as the heat delivery fluid the injection volumes are removed from the separator 610. Heat is delivered from a heat source 611, such as a boiler, into the heat exchanger 613. The small portion of the brine and/or oil 612 from the separator 610 is heated by the heat exchanger 613 and injected back into the well 600 a by way of the heat pipe 608, to merge with the cooling extracted oil to re-heat the oil and maintain the low viscosity of the oil as it rises through the oil production pipe 605.

Additionally, in contrast to the well 600 a, the well 600 b and its heating pipe 608 are extended deeper into the reservoir 607. One or more reservoir heating jets 616 are drilled into the bottom of the heating pipe 608 at one or more locations. The heated brine or oil that is pumped into the oil reservoir 607 into the reservoir heating jets 616 further heats the extractable oil and lowers its viscosity.

In the well 600 c shown in FIG. 13, the perforations are modified to add horizontal bores 617, which are drilled to improve the collection of the oil. These bore holes 617 can have slotted liners. A toroidal convection can be established which will increase the spread of heat and increase the flow of oil.

A heat delivery system efficiency example using any one of the wells described herein is as follows.

A well is provided with the following schematics:

-   -   Production Oil Pipe (“POP”) Diameter=6 inches     -   POP Area=28 square inches     -   Heating Pipe (“HP”) Diameter=1.5 inches     -   HP Area=1.77 square inches     -   Fluid Flow Rate of Oil & Brine=5,000 Bands per day (example)     -   Fluid Flow Rate of Oil & Brine=156 gallons per minute

Proportion Flow rate of PO after HP=1−((HP Area·2)/POP Area)≈87.5%

-   -   (assumes flow rates are equivalent)

Because the oil viscosity is the denominator of the pertinent formula described previously herein, if the viscosity is reduced by one-half, the flow rate is doubled. As shown in FIG. 1c , by heating the oil from a temperature of 150° F. to 300° F. the viscosity is reduced from 1,000 cP to 100 cP.

The net effect is as follows:

Flow=(156/(100/1,000))·0.875=1,365 (an increase of 8.7 times the original extraction rate)

Additional factors that impact the ability to change the flow rate include the pumping rate of the oil production pipe, the pumping rate of the heat pipes, the number and placement of the heating jets, the temperature of the injected brine/oil/gas, the viscosity of the extracting oil, the characteristics of the oil reservoir, and the heat conductivity of the oil production pipe, fill and casing. A more complex model can determine the parameters for optimization of the system that will make the flow of oil most efficient.

Referring back to previous embodiments that address heating the oil being extracted as it nears the top of the well, it should be realized that the fluid in the heating chamber that surrounds the oil production pipe may be heated by heating elements powered by electricity. Electrical current is passed through an electrical heating element placed in a fluid surrounding the oil production pipe. The element conducts and/or radiates heat to the oil production pipe via the fluid.

The electric power may be provided from any source but may also be generated as shown for instance in FIGS. 14-16 for both land based oil production well and for an offshore platform based oil production well.

One way to heat the oil is by means of electric heating resistant cables. Such a case is shown in FIG. 14 which represents a modification of the system shown in FIG. 13 as a land based oil production well modified for thermal heating with electric heating cables. As shown, instead of a heated fluid provided to a heat pipe as a heat source within a well as described in previous embodiments, the heat source of FIG. 14 is heating resistant cables 702 powered by electricity provided by electric cable 704. Heat 705 radiates into the fluid surrounding the oil production pipe 707 in the heating chamber 724 from the action of electric current passing through the resistance of electrified cables 702. Electricity may be generated by a generator such as a turbine generator 706. Gas 708 and/or crude oil 710 that are provided by a separator 712 may be used, for example, to fire a combustion turbine that pulls air in from the outside and compresses the air with a compressor attached to a shaft. The compressed air is then ignited by burning the gas in the pressurized air as it flows into a combustion chamber. The burning causes the air to expand as it flows into a turbine also attached to the common shaft. The expanding air pushes the turbine to spin as the air traverses the turbine. An electric generator may be connected to the common shaft and will generate electricity as its rotor spins. Although more efficient turbines are available, it is common for only about one third of the energy generated to be converted to electricity as the rest is used to turn the turbine that compresses the outside air. In the prior art, the exhaust gas is exhausted back to the outside atmosphere or sent to a recuperator to recover energy from the exhaust to, for example, preheat the compressor discharge before it enters the combustion chamber. According to the teachings hereof, the exhaust gas 716 or a part thereof may be mixed by a mixer (not shown) with brine 717 provided by the separator 712 that separates the oil 710, the gas 708 and the brine 717 from the oil/brine/gas flow 714 extracted from the earth by a pump 720 of the well. As in prior described embodiments, the brine and CO₂ mixture 718 is provided to the oil reservoir 722 to heat the reservoir and facilitate increased flow into the well from beneath the casing 711 and through perforations 709. The difference here is that the fluid above the seal (plug) 726 in the heating chamber 704 is heated by the heating resistant cables 702 that are in turn powered by electricity delivered on the electric cable 704 from the turbine-generator. It should be realized that the method of heating the fluid in the heating chamber shown in previous figures and discussed above may be replaced by the methods shown in FIGS. 14-16 or, instead of replacement, augmented by the methods of FIGS. 14-16 so that both any of the previously disclosed methods are used together with the electric heating methods of FIGS. 14-16.

Referring now to FIG. 15, an offshore version of the system of FIG. 14 is shown deployed on a platform 830 above the ocean 832 instead of the ground as in FIG. 14. The system of FIG. 15, comprising the elements labeled 802-826 operates in substantially same manner as the system of FIG. 14, with the corresponding elements labeled 702-726.

FIG. 16 shows an offshore heating cocoon 901 that wraps around a top segment of the under ocean portion of the oil well for a retrofitted system. The well is deployed from a platform 930 and is equipped with equipment having reference numerals 902-926 corresponding to the elements 702-726 of FIG. 14 and elements 802-826 of FIG. 15. The heating resistant cable 902, electric cable 904 and radiating heat 905 extend into the cocoon 901 rather than into the heating chamber 924. In this embodiment, the cocoon 901 is deployed so that it surrounds a lower, underwater part of the heating chamber 924 where the temperature of the ocean 932 will tend to draw heat away from the oil (tending to increase its viscosity) as it emerges from the earth into the production pipe 907 under the ocean. The cooling effect of the ocean 932 is counteracted by providing such a cocoon 901 to heat the ocean portion of the oil well from the surface under the platform 930 down to the bottom 935 of the ocean. The flow of oil is enhanced by counteracting the cooling effect of the cold ocean 932 temperature and thereby lowering its viscosity as it is pumped 920 up the oil production pipe 907 from the reservoir 922 beneath the bottom 935 of the ocean.

While there have been shown and described and pointed out fundamental novel features of the invention as applied to preferred embodiments thereof, it will be understood that various omissions and substitutions and changes in the form and details of the devices and methods described may be made by those skilled in the art without departing from the spirit of the invention. For example, it is expressly intended that all combinations of those elements and/or method steps which perform substantially the same function in substantially the same way to achieve the same results are within the scope of the invention. Moreover, it should be recognized that structures and/or elements and/or method steps shown and/or described in connection with any disclosed form or embodiment of the invention may be incorporated in any other disclosed or described or suggested form or embodiment as a general matter of design choice. 

What is claimed:
 1. A system for recovering oil, gas or oil and gas from a reservoir beneath a surface comprising: at least one production pipe for receiving the oil and gas in the reservoir; at least one pump configured to pump the oil and gas to the surface; a casing surrounding the at least one production pipe; and at least one heating element in parallel with the production pipe configured to provide heat to the oil and gas being pumped to the surface.
 2. The system according to claim 1, wherein the at least one heating element comprises one or more electric heating cables.
 3. The system according to claim 2, wherein the one or more electric heating cables are in a fluid heating chamber within the casing and surrounding the at least one production pipe, and the one or more electric heating cables radiate heat to the fluid heating chamber for heating the oil and gas being pumped to the surface in the at least one production pipe.
 4. The system according to claim 2, wherein the one or more electric heating cables extend into a heating cocoon surrounding a portion of the casing.
 5. The system according to claim 4, wherein the reservoir is underwater and the portion of the casing surrounded by the heating cocoon is underwater and the heating cocoon is configured to heat the water surrounding the casing and the at least one production pipe.
 6. The system according to claim 2, wherein the at least one pump is further configured to pump brine or water from the reservoir to the surface, and provide pumped oil, gas and brine to a separator configured to separate oil, gas and brine.
 7. The system according to claim 6, wherein a portion of the separated oil, gas or oil and gas is provided to an electricity generator to fuel the electricity generator.
 8. The system according to claim 7, wherein the portion of the separated oil, gas or oil and gas includes flared gas.
 9. The system according to claim 7, wherein the electricity generator provides electricity to the one or more electric heating cables.
 10. The system according to claim 9, wherein generation of electricity by the electricity generator creates an exhaust gas, and the exhaust gas is mixed with the separated brine to create a mixture of gas and brine that is injected into the reservoir to increase the flow of oil and gas in the reservoir to the at least one production pipe.
 11. The system according to claim 10, wherein the mixture of gas and brine is injected into a perforated pipe positioned in the reservoir beneath the casing.
 12. The system according to claim 1, wherein the at least one heating element comprises one or more heating pipes transporting a heating substance.
 13. The system according to claim 12, wherein the one or more heating pipes are in a fluid heating chamber within the casing and surrounding the at least one production pipe, and the one or more heating pipes include perforations and provide heat to the fluid heating chamber for heating the oil and gas being pumped to the surface in the at least one production pipe.
 14. The system according to claim 12, wherein the one or more heating pipes extend into a heating cocoon surrounding a portion of the casing.
 15. The system according to claim 12, wherein the one or more heating pipes include at least one heating pipe within the at least one production pipe.
 16. The system according to claim 12, wherein the at least one pump is further configured to pump brine or water from the reservoir to the surface, and provide pumped oil, gas and brine to a separator configured to separate oil, gas and brine.
 17. The system according to claim 16, wherein a portion of the separated oil, gas or oil and gas is provided to a heating source configured to heat a fluid.
 18. The system according to claim 17, wherein the portion of the separated oil, gas or oil and gas includes flared gas.
 19. The system according to claim 17, wherein the heat source is a boiler configured to heat a fluid.
 20. The system according to claim 19, wherein the heat source creates an exhaust gas, and the exhaust gas is mixed with the separated brine by a heat exchanger and mixer to create a mixture of gas and brine that is injected into the reservoir through the one or more heating pipes to increase the flow of oil and gas in the reservoir to the at least one production pipe.
 21. The system according to claim 20, wherein the mixture of gas and brine is injected into a perforated pipe positioned in the reservoir beneath the casing.
 22. The system according to claim 20, wherein the system further comprises a plurality of horizontal bore holes in the reservoir, and wherein the one or more heating pipes extend into the plurality of horizontal bore holes.
 23. A method for recovering oil, gas or oil and gas from a reservoir beneath a surface comprising: providing at least one production pipe for receiving the oil and gas in the reservoir and a casing surrounding the at least one production pipe; pumping oil and gas to the surface with at least one pump; and heating the oil and gas being pumped to the surface with at least one heating element in parallel with the production pipe.
 24. The method according to claim 23, wherein the at least one heating element comprises one or more electric heating cables.
 25. The method according to claim 24, wherein the one or more electric heating cables are in a fluid heating chamber within the casing and surrounding the at least one production pipe, and the one or more electric heating cables radiate heat to the fluid heating chamber for heating the oil and gas being pumped to the surface in the at least one production pipe.
 26. The method according to claim 24, wherein the one or more electric heating cables extend into a heating cocoon surrounding a portion of the casing.
 27. The method according to claim 26, wherein the reservoir is underwater and the portion of the casing surrounded by the heating cocoon is underwater and the heating cocoon is configured to heat the water surrounding the casing and the at least one production pipe.
 28. The method according to claim 24, further comprising pumping brine or water from the reservoir to the surface by the at least one pump together with the pumped oil and gas, providing the pumped oil, gas and brine to a separator, and separating the oil, gas and brine.
 29. The method according to claim 28, further comprising providing a portion of the separated oil, gas or oil and gas to an electricity generator to fuel the electricity generator.
 30. The method according to claim 29, wherein the portion of the separated oil, gas or oil and gas includes flared gas.
 31. The method according to claim 28, further comprising generating electricity by the electricity generator and providing electricity to the one or more electric heating cables.
 32. The method according to claim 31, wherein generation of electricity by the electricity generator creates an exhaust gas, and the method further comprises mixing the exhaust gas with the separated brine to create a mixture of gas and brine and injecting the mixture into the reservoir to increase the flow of oil and gas in the reservoir to the at least one production pipe.
 33. The method according to claim 32, wherein the mixture of gas and brine is injected into a perforated pipe positioned in the reservoir beneath the casing.
 34. The method according to claim 23, wherein the at least one heating element comprises one or more heating pipes.
 35. The method according to claim 34, wherein the one or more heating pipes are in a fluid heating chamber within the casing and surrounding the at least one production pipe, and the one or more heating pipes comprise perforations and provide heat to the fluid heating chamber for heating the oil and gas being pumped to the surface in the at least one production pipe.
 36. The method according to claim 34, wherein the one or more heating pipes extend into a heating cocoon surrounding a portion of the casing.
 37. The method according to claim 34, wherein the one or more heating pipes include at least one heating pipe within the at least one production pipe.
 38. The method according to claim 34, further comprising: pumping brine or water in the reservoir to the surface by the at least one pump together with the pumped oil and gas, providing the pumped oil, gas and brine to a separator, and separating the oil, gas and brine.
 39. The method according to claim 38, further comprising providing a portion of the separated oil, gas or oil and gas to a heating source configured to heat a fluid.
 40. The method according to claim 39, wherein the portion of the separated oil, gas or oil and gas includes flared gas.
 41. The method according to claim 39, wherein the heat source is a boiler configured to heat a fluid.
 42. The method according to claim 41, wherein the heat source creates an exhaust gas, and the method further comprises mixing the exhaust gas with the separated brine to create a mixture of gas and brine and injecting the mixture into the reservoir to increase the flow of oil, gas or oil and gas in the reservoir to the at least one production pipe.
 43. The method according to claim 42, wherein the mixture of gas and brine is injected into a perforated pipe positioned in the reservoir beneath the casing.
 44. The method according to claim 42, wherein the method further comprises: providing a plurality of horizontal bore holes in the reservoir, and extending the one or more heating pipes into the plurality of horizontal bore holes. 